Heat Rate Of Power Plant

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Theefficiency of a plant is the percentage of the total energy content of a power plant's fuel that is converted into electricity. The remaining energy is usually lost to the environment as heat unless it is used for district heating.

Depending on which convention is used, a differences of 10% in the apparent efficiency of a gas fired plant can arise, so it is very important to know which convention, HCV or LCV (NCV or GCV) is being used.

The term efficiency is a dimensionless measure (sometimes quoted in percent), and strictly heat rate is dimensionless as well, but often written as energy per energy in relevant units. In SI-units it is joule per joule, but often also expressed as joule/kilowatt hour or British thermal units/kWh.[3] This is because kilowatt hour is often used when referring to electrical energy and joule or Btu is commonly used when referring to thermal energy.

Heat rate in the context of power plants can be thought of as the input needed to produce one unit of output. It generally indicates the amount of fuel required to generate one unit of electricity. Performance parameters tracked for any thermal power plant like efficiency, fuel costs, plant load factor, emissions level, etc. are a function of the station heat rate and can be linked directly.[4]

Proposed U.S. standards for reducing carbon emissions from existing coal-fired power plants rely heavily upon generation-side efficiency improvements. Fuel, operations, and plant design all affect the overall efficiency of a plant, as well as its carbon emissions. This review of the fundamentals of coal plant efficiency, frequent problems that reduce efficiency, and some solutions for improving operation and reducing generation costs should be valuable to plants wherever they are located.

Fast-forward to 2014, and the scene is radically different. Advanced coal plant emissions controls are the norm, and PRB coal is in use to some extent at most power plants in the U.S., and the Environmental Protection Agency (EPA) has proposed standards for reducing carbon emissions from existing power plants under Section 111(d) of the Clean Air Act. Comprising a variety of possible methods for reducing carbon emissions, one building block of the EPA plan is improving net plant heat rate (NPHR) by 6% or greater. Although this may sound like a small number to the layperson, power plant engineers know that a 6% heat rate improvement would require a serious commitment on many different levels within their utility.

This article outlines the basics of plant efficiency and heat rate, such that one can quickly understand where the best opportunity for improvement is for a specific generating asset. It then examines ways in which the 6% NPHR goal might be achieved.

In the U.S., heat rate is typically expressed using the mixed English and SI units of Btu/kWh. Though confusing at first, this merely indicates how many Btu/hr of energy are required to produce 1 kW of useful work. Other countries commonly use kJ/kWh, kCal/kWh, or other measures. This article uses the U.S. format.

One of the simplest ways to calculate your NPHR is to divide the Btu/hr of fuel heat input by your net generation (electricity and steam to the customers) in terms of kW. However, determining the heat input can be quite difficult.

At one power plant I worked at, the only capability for estimating the coal burn rate was to rely on photographs of the coal yard taken by a spritely lady from her Cessna aircraft, and by comparing the estimated stockpile size with train receipts for the month to determine how much coal was burned overall. The potential error for this method could easily be greater than 25%.

In short, the input/output method is not an ideal method to track the difference in efficiency at your coal-fired power plant unless you have accurate coal feeders (Figure 1) plus an accurate and regular determination of your fuel heating value.

A significant problem with using the input/output method to determine your heat rate is that, should your heat rate change from one situation to the next, you have no idea of what led to the change. Was the boiler less efficient at burning the fuel? Is turbine efficiency reduced due to high condenser backpressure? Has station service power increased? Because the input/output method treats the power plant as a black box, the engineer must rely on a more accurate method of determining heat rate.

The heat loss method for calculating heat rate essentially draws a box around each of these subsystems and determines the efficiency of each energy conversion process. The product of all of these conversion efficiency values results in the total net plant heat rate for the power plant:

Determining your boiler efficiency is effectively determining all of the different inefficiencies resulting from the process of burning fuel to create steam energy. Standards and testing organizations such as the American Society of Mechanical Engineers (ASME) and Deutsches Institut fr Normung (DIN) have similar but different metrics for calculating efficiency losses, but from a general standpoint they can be grouped into the following categories.

Sensible Heat Loss. Sensible heat losses can be thought of as heat you can sense directly with a thermometer. For example, combustion air enters your power plant at ambient conditions, and flue gas is exhausted from the cold end of the boiler air heater at some elevated temperature. The closer the exhaust gas is to ambient temperature, the less sensible heat is lost to the environment.

Other sensible heat losses include the heat contained in bottom and fly ash removed from the boiler and pyrites and rock that are rejected from coal mills. The quantity of excess air used for combustion has a significant effect on this loss, as every pound of excess air that travels through the boiler carries with it potentially usable energy.

Latent Heat Loss. Latent heat losses are not easily detectable by a thermometer and are energy losses associated with a phase change of water. When a fuel is burned in a boiler, not only does all moisture contained within the fuel vaporize into steam, but all hydrogen contained within the fuel combusts to form water, which also is vaporized into steam. Unless the temperature of the exhaust gas leaving the boiler air heater is below the boiling point of the water contained within the gas, all of that latent heat of vaporization will exit the boiler and be lost to the environment.

Unburned Combustible Loss. Unburned combustible losses are efficiency losses from incomplete combustion of fuel in the boiler. This is primarily measured in the form of carbon residue in the ash, but it also includes carbon monoxide (CO) production. These losses are generally influenced by both fuel properties (fuel volatility) and operations practices (excess air level, fuel fineness, and the like). It is important to note that unburned combustible loss is not the same as loss-on-ignition (LOI), as unburned combustible loss is an energy loss, whereas LOI is calculated on a mass basis in the ash.

Radiation and Convection Loss. Utility boilers are enormous equipment systems, with numerous penetrations for tubes and instruments, and a very large surface area exposed to the environment. As a result, no matter how well-designed the insulation is and how diligent plant personnel are in fixing air leaks, energy will still be lost via radiation and convection.

Improving Boiler Efficiency. Sensible heat losses can be reduced by installing improved combustion controls to allow fine-tuning the excess air level in the furnace operators to reduce the excess oxygen level in the furnace. Preheating combustion air with waste heat from the plant will also increase efficiency, and some plants are considering schemes to use solar thermal collectors as air preheaters during daylight hours.

As latent heat losses are strongly tied to fuel quality, and current boiler designs do not allow for condensing air heaters, outside of switching to a dryer fuel, there is little that can practically be done to reduce latent heat losses.

Unburned combustible losses can be reduced by improved boiler and burner tuning, with some plants able to gain more than 1% in net efficiency as a result of a minor amount of tuning or capital investment.

Your turbine efficiency is essentially the efficiency of the turbine to convert steam from the boiler into usable rotational energy. A simplified way of viewing your net turbine heat rate (NTHR) is to sum the enthalpy increases of the feedwater and the cold reheat steam across the boiler boundary and divide this by the gross electrical generation.

Improving Turbine Cycle Efficiency. Under ideal conditions, an ultra-supercritical turbine cycle system can convert steam into rotational energy at 54% or higher efficiency, supercritical turbine cycles can achieve 50% efficiency, and subcritical turbine cycles can achieve 46% efficiency. However, the turbine cycle system of your power plant is at least as complex as your boiler system, and there are numerous places for efficiency to be lost.

Bucket tip and packing leakage can constitute 40% of total efficiency loss within the turbine. Nozzle roughness, erosion, and repair can account for 35% of efficiency loss, turbine deposits 15%, and bucket erosion and roughness 10%. Problems in these areas can result in significant efficiency losses: Turbine deposits have been known to cause nearly a 5% efficiency loss and turbine casing leaks as much as a 3% efficiency loss.

Turbine blade improvements are available for most steam turbines, with improvements of up to 2% possible with a complete replacement of the low-pressure turbine. Even renewable energy can assist with heat rate improvement, as some generators have explored the prospect of solar feedwater heating to boost their turbine cycle efficiency, with some designs able to achieve a peak efficiency improvement of more than 5%. Of course, with all upgrades, you have to examine the economics (see sidebar).

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